In drilling a borehole in the earth, such as for the recovery of hydrocarbons or for other applications, it is conventional practice to connect a drill bit on the lower end of an assembly of drill pipe sections that are connected end-to-end so as to form a “drill string.” The bit is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating bit engages the earthen formation causing the bit to cut through the formation material by either abrasion, fracturing, or shearing action, or through a combination of cutting methods, thereby forming a borehole along a predetermined path toward a target zone.
Many different types of drill bits have been developed and found useful in drilling such boreholes. Two predominate types of drill bits are roller cone bits and fixed cutter (or rotary drag) bits. Most fixed cutter bit designs include a plurality of blades angularly spaced about the bit face. The blades project radially outward from the bit body and form flow channels therebetween. In addition, cutting elements are typically grouped and mounted on several blades in radially extending rows. The configuration or layout of the cutting elements on the blades may vary widely, depending on a number of factors such as the formation to be drilled.
The cutting elements disposed on the blades of a fixed cutter bit are conventionally formed of extremely hard materials. In a conventional fixed cutter bit, each cutting element has an elongate and generally cylindrical tungsten carbide substrate that is received and secured in a pocked formed in the surface of one of the blades. The cutting elements also generally include a hard cutting layer of polycrystalline diamond (PCD) or other superabrasive materials such as thermally stable diamond or polycrystalline cubic boron nitride. For convenience, as used herein, reference to “PDC bit” or “PDC cutters” refers to a fixed cutter bit or cutting element employing a hard cutting layer of polycrystalline diamond or other superabrasive materials.
Referring to FIGS. 1 and 2, a conventional fixed cutter or drag bit 10 adapted for drilling through formations of rock to form a borehole is shown. Bit 10 generally includes a bit body 12, a shank 13, and a threaded connection or pin 14 for connecting the bit 10 to a drill string (not shown) that is employed to rotate the bit in order to drill the borehole. Bit face 20 supports a bladed cutting structure 15 and is formed on the end of the bit 10 that is opposite pin end 16. Bit 10 further includes a central axis 11 about which bit 10 rotates in the cutting direction represented by arrow 18.
Cutting structure 15 is provided on face 20 of bit 10. Cutting structure 15 includes a plurality of angularly spaced-apart primary blades 31, 32, 33, and secondary blades 34, 35, 36, each of which extends from bit face 20. Primary blades 31, 32, 33 and secondary blades 34, 35, 36 extend generally radially along bit face 20 and then axially along a portion of the periphery of bit 10. However, secondary blades 34, 35, 36 extend radially along bit face 20 from a position that is distal bit axis 11 toward the periphery of bit 10. Thus, as used herein, “secondary blade” may be used to refer to a blade that begins at some distance from the bit axis and extends generally radially along the bit face to the periphery of the bit. Primary blades 31, 32, 33 and secondary blades 34, 35, 36 are separated by drilling fluid flow courses 19.
Referring still to FIGS. 1 and 2, each primary blade 31, 32, 33 includes blade tops 42 for mounting a plurality of cutting elements, and each secondary blade 34, 35, 36 includes blade tops 52 for mounting a plurality of cutting elements. In particular, cutting elements 40, each having a cutting face 44, are mounted in pockets formed in blade tops 42, 52 of each primary blade 31, 32, 33 and each secondary blade 34, 35, 36, respectively. Cutting elements 40 are arranged adjacent one another in a radially extending row proximal the leading edge of each primary blade 31, 32, 33 and each secondary blade 34, 35, 36. Each cutting face 44 has an outermost cutting tip 44a furthest from blade tops 42, 52 to which cutting element 40 is mounted.
As shown in FIGS. 1 and 2, each gage pad 51 includes a generally gage-facing surface 60 and a generally forward-facing surface 61 which intersect in an edge 62, which may be radiused, beveled or otherwise rounded. Gage-facing surface 60 includes at least a portion that extends in a direction generally parallel to bit axis 11 and extends to full gage diameter. Other portions of gage-facing surface 60 may also be angled, and thus slant away from the borehole sidewall. Also, forward-facing surface 61 may be angled relative to central axis 11 (both as viewed perpendicular to central axis 11 or as viewed along central axis 11). Surface 61 is termed generally “forward-facing” to distinguish that surface from the gage surface 60, which generally faces the borehole sidewall. Gage-facing surface 60 of gage pads 51 abut the sidewall of the borehole during drilling. At least some gage pads 51 may include cutting elements. No gage pads 51 may be provided on bit 10. Wear-resistant inserts may be embedded in gage pads 51 and protrude from the gage-facing surface 60 or forward facing, surface 61 of gage pads 51.
Referring now to FIG. 3, a profile of bit 10 is shown as it would appear with each blade (e.g., primary blades 31, 32, 33 and secondary blades 34, 35, 36) and cutting faces 44 of each cutting element 40 rotated into a single rotated profile. In rotated profile view, blade tops 42, 52 of blades 31-36 of bit 10 form and define a combined or composite blade profile 39 that extends radially from bit axis 11 to outer radius 23 of bit 10. Thus, as used herein, the phrase “composite blade profile” refers to the profile, extending from the bit axis to the outer radius of the bit, formed by the blade tops of each of the blades of a bit rotated into a single rotated profile (i.e., in rotated profile view).
Conventional composite blade profile 39 (most clearly shown in the right half of bit 10 in FIG. 3) may generally be divided into three regions labeled cone region 24, shoulder region 25, and gage region 26. Cone region 24 comprises the radially innermost region of bit 10 and composite blade profile 39 extending generally from bit axis 11 to shoulder region 25. As shown in FIG. 3, in most conventional fixed cutter bits, cone region 24 is generally concave. Adjacent cone region 24 is shoulder (or the upturned curve) region 25. In most conventional fixed cutter bits, shoulder region 25 is generally convex. Moving radially outward, adjacent shoulder region 25 is the gage region 26 which extends parallel to bit axis 11 at the outer radial periphery of composite blade profile 39. Thus, composite blade profile 39 of conventional bit 10 includes one concave region (cone region 24), and one convex region (shoulder region 25).
The axially lowermost point of convex shoulder region 25 and composite blade profile 39 defines a blade profile nose 27. At blade profile nose 27, the slope of a tangent line 27a to convex shoulder region 25 and composite blade profile 39 is zero. Thus, as used herein, the term “blade profile nose” refers to the point along a convex region of a composite blade profile of a bit in rotated profile view at which the slope of a tangent to the composite blade profile is zero. For most conventional fixed cutter bits (e.g., bit 10), the composite blade profile includes a single convex shoulder region (e.g., convex shoulder region 25), a single one blade profile nose (e.g., nose 27). As shown in FIGS. 1-3, cutting elements 40 are arranged in rows along blades 31-36 and are positioned along the bit face 20 in the regions previously described as cone region 24, shoulder region 25 and gage region 26 of composite blade profile 39. In particular, cutting elements 40 are mounted on blades 31-36 in predetermined radially-spaced positions relative to the central axis 11 of the bit 10.